I am a registered investment advisor based in Houston Texas, specializing in equity options. My focus is naked put selling and spread trading. I have past experience in commercial banking, real estate, and oil and gas, as well as various types of other derivative investments. My world was turned upside down by the financial crisis of 2008-9. Many of my views are slanted to expose and correct the corruptions existing in the world’s financial markets. I have a BS in economics from UC Berkeley and an MBA in finance from the U of Pennsylvania Wharton School. Reach me at rbf10@comcast.net

$8 Natural Gas: We're Right On Schedule

New natural gas rig counts hit the wires Friday morning and on cue the number decreased yet another 15 rigs to 422, another 21st century low and a massive 55% below the 936 peak one year ago. An article was published by me on July 22nd predicting a spike to $8.00 natural gas by this winter. Well, we are right on track. During that July week natural gas storage numbers were 19.2% and 17.5% respectively above the one and five year averages. Back then we had had eleven straight weeks of below normal storage injections. Since that time we have had a look at thirteen more data points twelve of which were below normal so now the “glut” has diminished to only 6.8% and 7.8% more than the one and five year averages. Thursday’s actual storage injection was 72 Bcf against a 108 Bcf increase one year ago this week.

I have continued to inspect decline curves for wells in the Eagle Ford shale. After viewing records for over 70 wells with between nine and eighteen months of production data, the declines continue to be precipitous. A one year decline rate of 80% or more was more the norm than the exception for the data I inspected. In other words a well making 800 BOE (barrels of oil equivalent) on day one, more likely than not was generating well under 200 BOE twelve months later. So I wondered whether there was any recent literature to corroborate my own empirical evidence. Gary Swindell a Dallas, Texas petroleum engineer did an Eagle Ford shale study analyzing 1,041 wells in ten Eagle Ford shale counties with current drilling activity. Similar to my own findings he found decline rates on average were 76%. But he explored much deeper to determine if Estimated Ultimate Recovery (EUR) of a well was dependent on such metrics as frac size in thousands of pounds of sand, distance of the perforated length of the horizontal drill pipe, and the well’s Initial Potential or IP. The conclusion was there was some correlation between more oil and gas produced and bigger and longer fracs up to a point at which time there were diminishing returns. For example, Fracs over 5,000 feet horizontally generally showed lesser returns as did Fracs using over 6,000 pounds of sand. The IP represents the initial production of those first few test days when the well produces at its highest outputs. Swindell also did a simple time test. Were wells getting better, meaning more productive as time passed? Was experience and technology increasing drilling efficacy? Back in July there were lots of criticisms on my previous article claiming how much more efficient drilling is today which more than offsets the dwindling rig supply. The evidence concluded than up until 2010, in the Eagle Ford at least, wells indeed improved, but subsequent to that there has been a plateauwith no increaesed productivity gains for over two years.

The most stunning and damning discovery by far was that of the 1,041 wells, the average EUR was only 206,779 BOE per well. Not surprisingly most public companies tend to report or advertise only their IP on a well which is all the SEC and the Texas Railroad Commission requires. They may throw investors a bone and report the first 30 days average production. Many public exploration firms active in the Eagle Ford such as Marathon may publicize EUR’s as high as 340,000 to 500,000 BOE. To my knowledge, no public companies are reporting such rapid well decline rates as are shown in both my limited study and the Swindell report. For investors and analysts to make informed decisions companies should make public after three and six months both the well flow rate (how much the well has declined from IP) and more importantly the surface flowing pressure. Rapidly declining pressure is indicative of a shorter well life and is a predictive measure of well decline rates. Therefore if there really are significantly lower EUR’s than the world has come to take for granted, then the whole shale oil and gas economics must be revisited. While we have proven there are gas vast reserves to be mined, at what price levels does it make sense to pursue these opprtunities?

These wells are a mixture of both oil and gas. The study goes through February of 2012. Swindell actually does something kind of weird. The energy or British Thermal Unit (Btu) equivalent of 1 barrel of oil is (Bbl) 6,000 cubic feet of natural gas or 6 Mcf. But because of the huge price differential between oil and gas (it was even more pronounced back then) Mr. Swindell chooses to use a ratio of 20 Mcf to equal 1 Bbl of oil. Therefore when I convert his oil and gas computations (using his 20 to 1 ratio) into a straight natural gas well it shows that each well brings in on average 3.4 Bcf of natural gas reserves. Using the true Btu equivalent ratio would yield even lower reserve numbers. Anyway, the typical 8,000 to 12,000 feet below surface well, be it in the South Texas Eagle Ford or the East Texas/North Louisiana Haynesville play costs plus or minus $10 million. At $4.00 gas this is gross revenue of $13.6 million before deducting a ¼ or 25% royalty payment to the landowners, 7.5%Texas severance tax, 2.5% ad valorem taxes, and well operating expenses. I nearly forgot the pipeline prep to clean the gas of deadly H2S (Hydrogen Sulfide) and CO2 (carbon dioxide) and to rid excess water to below 7 ppm (parts per million.) Now it is ready for the KMP or KMR high pressure pipeline. All this costs about $.25. So you are left with about 60% or $2.40 or $8.16 million for your $10 million investment. At $5.00 Mcf gas you break about even and at $6.00 gas the compounded return is under 5%. Don’t forget it takes ten years or more to get most of your money back. There are a lot of pro-forma numbers that have estimated the EUR at Eagle Ford and Hayneville shale plays to be 6 Bcf or almost twice what the studies are showing. In fact 6 Bcf per well was the assumption used in my July article. Also keep in mind gas has only just recently spiked to close to $3.60 and has spent much of the last month or two near $3.00 or below. Drilling for it continues to be a very bad deal.

The Future

We have six or seven more weeks left in the shoulder season. Our current storage is 236 Bcf higher than last year. With six weeks left, storage injections must average just under 40 Bcf less than last years numbers. I think we will end up below last year’s storage but we can debate, and like Biden and Ryan vociferously disagree. Anyway, let’s compromise and assume storage levels end the shoulder season 120 Bcf above last year. And let’s say we have a normal winter. With what may be less than 400 gas rigs in operation, sooner rather than later supplies will get very strained and a price spike is highly likely. How have we had 23 of the last 24 weeks of below normal storage injections unless gas supplies are slowly and inexorably becoming strained? My thoughts are that the drilling done five and six months ago, that came on line three and four months ago is now going into a very rapid decline period that will soon show up in monthly production numbers. If we have any kind of an early cold snap, 400 rigs will not be able to alleviate tight supplies. We need gas sustainable from $4.50 to $5.00 Mcf to get the gas rig fleet re commissioned.

The US Energy Information Association (EIA) household fuel consumption estimates for October 2012 through March 2013 forecasts between 5 and 30% more heating days than the comparable 2011-2012 period. Even the staid EIA predicts 2012 overall demand to increase 4.7% to 69.76 Bcf/day which is in excess of their overall 2012 calculus for gas supply of 68.8 Bcf/day. Time will tell but the tipping point is near.

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What about the microturbine procuring E&Ps in the US shale plays? Aren’t they’re going to be burning more and more of that pesky dry gas as the play develops. Makes a lot more sense for those producers to use that dry gas to generate the electricity they need than to sell it for peanuts.

“Capstone continues its penetration of the North American shale gas market with two more large multiple megawatt orders – one from a new customer that ordered five C1000 Power Packages for five separate remote central gathering sites and a second from a producer with multiple Capstone microturbines already in the field. This latest follow-on order includes seven C600 and one C800 Power Packages. Capstone distributor Horizon Power Systems secured the two large orders the first week of April for the 13 Power Packages, which will supply prime power at each central gathering site. All 13 of the Power Packages are scheduled to be installed and commissioned in the next three months. “These Eagle Ford producers are continuing to adopt the Capstone microturbines because they want the high reliability and low emission benefits of our products,” said Sam Henry, Horizon Power Systems President. “They need the assurance of round-the-clock power at remote wellhead sites and know that’s precisely what Capstone microturbines deliver.”

If you look at the distribution of the wells sampled in this report and compare it to Marathon’s EF position, you will notice that there is a large hole of data missing.. Marathon does not have any leases in La Salle, Dimmit, Maverick, or Webb. The majority of its position is located in that large circle of missing data around the word “Karnes” on the map located on Page 2. There is a masive difference in EUR’s in northern Karnes versus this sweet spot.. I would suggest doing more research before calling out a specific company.. There are only about 50-100 data points out of the entire 1,000 well sample that are adjacent to Marathon leases.. If you would like some other oil and gas articles fact-checked, I would be happy to help.

There seems to be a contradiction in your article with respect to stated decline curves and “the time to get your money back”.

Initial decline rates of 75%-80% have been documented for years, this has been well understood. I am puzzled how you can conclude that “Don’t forget it takes ten years or more to get most of your money back” when you apply a 75% decline rate as in year 4 the production (=revenue) stream is 1.6% of what it was in year 1? Clearly, if these wells are to be economic the cost recovery is tremendously front end loaded.

Could you address this apparant contradiction or am I misunderstanding your thesis with respect to payout times?

After a precipitous first year decline, production should level off and decline much more slowly…..but it depends on the well pressure levels. There are no well that have even 5 years of data so we don’t know what the ultimate recoveries will be or how long each well will last. But the cost recovery is front end loaded. Thanks for your comment. Richard

Your assessment that gas will spike to $8 in the next 6 months, or even 12 months is absurd. I feel you are looking at the natural gas market with blinders. How are EUR and production models from the Eagle Ford ( a liquids rich play) and the Haynesville being applied to the rest of the country? As I am sure you may live in the Northeast, the amount of use of natural gas in the Northeast part of the country is a dominant factor in the NYMEX price of natural gas. So why are you not looking also at the Marcellus? The Marcellus is one of the largest contributors to domestic natural gas prodution onshore. I also think you need to research how many wells have been drilled and not yet completed, or they are drilled, completed, but shut in until natural gas prices are higher. I, Sir, work for a large independent oil and gas company and this gross misinterpretation of onshore natural gas production leads your readers in the wrong direction, put together with the elementary reservior engineering you attempt at, that I do think you need to research more on.

As prices inch closer to $4 or $5 you will definitely see more gas come online as Marcellus wells are starting to come online as they open up the wells or even open up the chokes on the valves. Also you may see increased rates of completions on wells that have been drilled, but not completed yet. Natural gas wells that are shut in, not completed, or choked back is a large production number you are not factoring in. I suggest you seek industry assistance in your analysis before leading your readers astray next time. Thank you.

I do not dispute the overall natural gas supply in the US. With regard to Eagle Ford there is lots of dry gas most notably in Webb county and the decline rates have matched those of liquids. Hayneville dry gas has had precititous decline rate as well. Marcellus is prolific but are they drilling new prospects at $3.50 gas? With regard to all the shut in or completed wells, show me the data. So far that is just a bunch of rumor. I maintain we will have a short term supply issue before the rig fleet kicks in to drive prices lower. If I anm wrong you can say I told you so. Thanks for your great comment. Richard

Listening to CHK’s Conference call…..CHK still having over 200 wells WOC in Eagle Ford, roughly 90+ wells waiting on completion or hookup in Utica, just for example. Haynesville production is expected to decline only 9% next year……..so just using one of the largest producers of natural gas, increased drilling in Niobrara and deep prospects in the Powder River Basin with them and other companies, with associated gas with the oil/condensate, how is gas going to get $8 again? So the data is in the industrys’ conference calls and presentations.

I think it might have been wise to suggest “that if the upcoming winter is not normal, Ng might register 2.50 before the spring. I think you may be a good journalist and it seems you are not afraid of doing research. Certainly you are not afraid to make predictions and well, they are what they are. The wiser we get the less prone we are to make them. I would suggest however that in a financial magazine with a stature as Forbes has, I find the comments not once but twice irresponsible. Everyone was on the horse while the trend was up. You unfortunately find yourself in some not so reputable company. When you eat crow, please forward me a copy. Avery1@mac.com